Oil sand deposits, located in many regions of the world, comprise mixtures of sand, water, clay, minerals, and crude bitumen that can be extracted and processed for fuel. The oil sands of Alberta, Canada, contain some of the largest deposits of hydrocarbons in the world.
Bitumen is classified as an “extra heavy oil,” referring to its gravity as measure in degrees on the American Petroleum Institute (API) scale. Bitumen has an API gravity of about 10° or less. The bitumen mined from the Athabasca oil sands of Alberta has an API gravity of about 8°. “Heavy oil” has an API gravity in the range of about 22.3° to about 10°. Heavy oil or bitumen extracted from oil sand is processed or upgraded to produce light synthetic crude oil having an API gravity of about 31° to about 33°. The terms heavy oil and bitumen are used interchangeably herein since they may be extracted using the same processes.
Bitumen can be recovered from the oil sands by various methods, the most common of which include surface or strip mining and in-situ bitumen recovery methods, including thermal in-situ recovery methods. The operations for recovery and extraction of bitumen are highly water intensive, thus facilities must generally draw from a dedicated water source, such as a nearby river or lake. The waste, including water waste, produced during these operations, is disposed of in tailings ponds, sludge lagoons, disposal wells and the like. There is a demand in the industry to reduce water consumption and waste associated with bitumen recovery and extraction processes and to minimize the overall land footprint and environmental impact of these operations.
There may be environmental restrictions placed on heavy oil/bitumen extraction operations that utilize fresh water. These restrictions relate to the amount of fresh water that can be removed from a source in the environment of the operation, such as from a lake, river, or fresh water aquifer. In some instances, the amount of fresh water that can be withdrawn may be a rate-limiting factor in the overall production of the operation. In such an instance, efficient re-use of water can directly impact the production of an operation.
Extracted bitumen may be pumped via pipeline to an upgrader on site or to a refinery for cleaning, treatment and upgrading. Upgrading of bitumen or heavy oil to a light synthetic crude oil is generally accomplished via carbon rejection (i.e. coking) or hydrogen addition. The latter process is typically a two-stage process involving hydrocracking to break down the large hydrocarbon molecules and hydrotreating to stabilize the hydrocarbon compounds and remove impurities. The upgraded synthetic crude oil can be sold to refineries, petrochemical manufacturers or other consumers.
Bitumen extraction operations require expensive and elaborate processing facilities and an abundance of water, as well as energy for heat and steam generation. On average, one and a half to two tons of oil sand must be processed to produce one 159-liter barrel of synthetic crude oil from bitumen. Large quantities of oil sand must be mined and processed each day in order to supply the high demand for synthetic crude oil.
In-situ oil recovery methods, such as thermal in-situ recovery methods, are applied when the bitumen is buried deep within a reservoir and cannot be mined economically due to the depth of the overburden. In-situ production methods may recover between about 25 and 75 percent of the bitumen initially present in a reservoir. In general the focus of an in-situ recovery process is to reduce the viscosity of the bitumen or heavy oil to enable it to flow and be produced from a well.
Thermal in-situ recovery processes use heat, typically provided by steam, to reduce the viscosity of the bitumen in a reservoir and thereby render it more flowable. Examples of thermal in-situ recovery processes include but are not limited to steam-assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), and various derivatives thereof, such as solvent-assisted SAGD (SA-SAGD), steam and gas push (SAGP), combined vapor and steam extraction (SAVEX), expanding solvent SAGD (ES-SAGD), constant steam drainage (CSD), and liquid addition to steam enhancing recovery (LASER), as well as water flooding and steam flooding processes.
In typical gravity-driven thermal in-situ oil recovery processes, two horizontal wells are drilled into the reservoir. A lower horizontal well, ideally located near the bottom of the reservoir, serves as a production well and a horizontal well located above the production well serves as an injection well. Dry or wet steam is injected into the injection well from the surface to heat the bitumen trapped in the reservoir and lower its viscosity. An enormous quantity of steam must be generated for this process and the water used for steam generation in conventional processes must meet boiler feed water specifications. As the viscosity of the bitumen is lowered, it flows into the production well, along with condensed steam, and these liquids are pumped to the surface. A hydrocarbon solvent or other agent may optionally be injected to assist the process.
The hot production fluids, typically comprising about 70% produced water and about 30% bitumen and produced gases, are recovered to the surface via the production well and are separated into their individual components on site. Production fluids from the wellhead are sent to a flow splitter to separate the bitumen, produced water and optionally produced gas into individual streams. A diluent or condensate is added to the bitumen stream to facilitate the removal of residual water from the oil. The diluted bitumen (“dilbit”) may be further treated or stored on site before being transported to an upgrader or pipelined to a refinery. The produced gas stream may be used to provide fuel for the steam generators.
The produced water (PW) stream is typically sent to water treatment facilities to make boiler feed water of suitable quality for steam generation. In this process, the PW stream is first deoiled and is then sent for softening treatment. The conventional approach used to treat or soften the produced water to meet boiler feed water specifications is a two-step process involving primary hardness removal followed by secondary hardness removal to polish the water.
This conventional configuration results in numerous waste streams that must be handled and the residual waste is ultimately sent to a disposal well or costly sludge lagoon on site.
There is an economic incentive for improving efficiencies in the bitumen and heavy oil industry in general and, in particular, for reducing capital and operating costs, water consumption, land footprint and the environmental impact associated with bitumen recovery operations. While attempts to reuse and recycle water for improved efficiency within an in-situ recovery operation, or within a mining operation, have been made, advantages to be achieved by integrating an in-situ operation with hydrogen production have not been fully appreciated.
There is a need to generate steam and hydrogen for the steam-assisted extraction of the heavy hydrocarbons from the hydrocarbon-containing reservoir and upgrading of the extracted heavy hydrocarbons.
It is desirable to provide new and improved methods and systems for improving efficiencies in water and energy consumption and also to reduce environmental impact of water consumption and waste disposal associated with bitumen mining and in-situ recovery operations, and reduce capital and operational costs. The reduction of the carbon intensity of bitumen production through efficiency gains or carbon dioxide capture is important for environmental reasons and for maintaining the marketability of bitumen-derived fuels.
There is a need for technologies which capture and re-use water so as to minimize input of fresh water. Industry desires to conserve/minimize the amount of water used for steam injection at hydrocarbon extraction sites.
Sites for heavy hydrocarbon extraction and upgrading of the heavy hydrocarbons are generally remote and co-production of electricity for use in the production facility is sometimes desired as well.
Industry desires improved energy efficiency for the production of steam, hydrogen, and/or electricity.
Industry desires the ability to adjust one or more of the various ratios of steam:hydrogen, steam:electricity produced at a site.
Industry desires uninterrupted supply of hydrogen for upgrading heavy hydrocarbons.
The present invention aims to satisfy one or more of these and other desires of industry.